先鋒自然資源 (PXD) 2018 Q3 法說會逐字稿

Good day, ladies and gentlemen. Welcome to Pioneer Natural Resources Third Quarter Conference Call. Joining us today will be Tim Dove, President and Chief Executive Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Neal Shah, Vice President, Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select Investors, then select Earnings and Webcasts. This call is being recorded. A replay of the call will be archived on the Internet site through December 2, 2018.

The company's comments today will include forward-looking statements made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on Page 2 of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission.

At this time, for opening remarks, I would like to turn the call over to Pioneer's Vice President of Investor Relations, Neal Shah. Please go ahead, sir.

Thank you, Greg. Good morning, everyone, and thank you for joining us. Let me briefly review the agenda for today's call. Tim will be up first. He will provide the financial and operating highlights for the third quarter of 2018, a strong quarter of execution for Pioneer, and our latest outlook for the remainder of the year. After Tim concludes his remarks, Joey will review our strong horizontal well performance in the Permian Basin, including our recent successful Stackberry appraisal results. Rich will then update you on our firm transportation commitments to move oil from the Midland to the Gulf Coast and the financial benefits we are receiving. Rich will also cover the third quarter financials and provide earnings guidance for the fourth quarter. Tim will then return with a brief recap and general commentary on 2019. After that, we will open up the call up for your questions. Thank you.

So with that, I'll turn it over to Tim.

Thanks a lot, Neal. On any objective measure, the third quarter was an exceptionally strong quarter for Pioneer. We substantially beat consensus on earnings and EBITDA, and cash flow for the quarter exceeded our capital spending, all of which are huge positives for PXD.

Earnings were very robust at $355 million on an adjusted basis or $2.07 per diluted share. Total Permian production met the top end of the range that we had provided for the quarter. And importantly, Permian oil production exceeded the top end of the range growing by 7% quarter-over-quarter. Due to that exceptionally strong execution during the quarter, the number of wells that we put on production exceeded our estimates where we placed -- sorry, 69 horizontal wells on production. As a result, the balance sheet remains very strong with significant cash on hand and very low debt statistics. And in fact, net debt was reduced by $200 million this year -- this quarter on a quarter-to-quarter basis.

Turning to Slide 4. The company continues to benefit from its long-term planning approach, particularly regarding our FT program for oil deliveries to the high-priced Gulf Coast and export markets. And for the quarter, that benefit resulted in about $200 million of incremental cash flow for the third quarter. The number is expected to come down to about $125 million in the fourth quarter. That's simply a product of the differentials having tightened in the fourth quarter as compared to those numbers in the third quarter.

We're still continuing to deliver quite a large volume of oil to the Gulf Coast, about 165,000 BOE a day, barrels of oil per day in the third quarter under those same FT contracts, and about 130,000 MBOPD were exported. Those numbers will be increasing. In fact, our FT capacity goes up beginning November to 185,000 barrels of oil per day and over 200 in early 2019. So this will become an even bigger part of our results as we move forward, and we continue to see the benefits of incremental pricing as a result.

One of the things we've then seen is that about 90% of these volumes, over 90% of our volumes will be on FT contracts, and those receive Brent-related pricing. So that's a tremendous positive for the company. And as we discussed on our last call for the second quarter, we have no exposure today for Midland oil pricing through 2020. That kicked in really in September.

Similarly, on natural gas, the company has benefited greatly from FT to western markets where we received an uplift of about $1 per MCF versus -- that is if we had [let] the gas into Waha, into Waha sales areas for the whole third quarter. From an operational standpoint, Joey will cover this in a lot more detail, but the results look very promising for our first Stackberry pad. You may recall, we're drilling a total of 3 sets of these pads, the first of which we're reporting on today. The objective, of course, is to determine how to optimally space the -- and stagger and sequence the Middle Spraberry Shale, the Jo Mill and Lower Spraberry Shale intervals for longer-term development. Of course, we've drilled wells in all these zones and they've been excellent wells. And now, we're proving we can drill even better wells as we stagger and space these properly. The idea is to continue to add significant returns as we incrementally go into development mode on wells, and we're not facing as a result any sort of parent-child issues. In fact, to the contrary, we're actually making better wells. So the idea here is to not be drilling wells in a situation where we're just simply adding low return down-spaced wells that essentially overcapitalize a given rock volume. We're focused on incremental high returns on each individual well.

Going to Slide 5 then. As we reported in the second quarter call, we will soon add 2 rigs in December that are focused really more or less on 2019 production. In fact, since we're just coming here at the end of the year, for this year, 2018, we still expect the POP range to be 250 to 275 wells.

Margins look very strong. IRRs continue to be at very high levels, especially when you consider the FT uplifts that I mentioned a minute ago. We're still on track to place 60 Version 3.0+ wells online for the second half of this year. Fortunately, we completed 44 of those and placed 39 of them on production in the third quarter. Joey will show you more details on that, but the results look really phenomenal as we have gotten to a point we think we've reached an optimal place when it comes to these high-volume completions.

We also reported in mid-September that we've entered into a long-term West Texas supply agreement for sand with U.S. Silica. It will represent 30% to 40% of our sand supplies when this kicks in, in the first quarter of 2019 at roughly half the cost of our average current supply of sand. As we continue to look at the benefits of reducing sand costs, it can have very dramatic improvements on our well economics as we drop the costs of those wells related to the sand volumes.

Then going to Slide 6. As an update on the divestiture process, we're pleased to have announced that we closed on several sales earlier this year, but we've also most recently, a week ago, announced the signing of a purchase and sale agreement regarding our remaining South Texas oil assets, we refer to them as the Sinor Nest assets for a net $132 million; that should close in the first half of December. We are continuing to make progress on the divestiture of our remaining Eagle Ford assets as well.

The 2018 capital program remains at about $3.4 billion. In essence, what that is, is spending our operating cash flow. So $3.4 billion is the current estimate of our operating cash flow for this year, and that will also be funded if needed from asset divestitures. But in other words, we expect 2018 in the year sense to be essentially cash flow neutral at year-end, which is a great step in the right direction. And 2018 production trajectory looks essentially the same as it has been, which is in the 19% to 24% range, trending towards the upper half of that range.

For the first time, we're talking about our returns on capital employed. You will see in the slide here that we're focusing on an ROCE number expected to be above 10% for the year, that was about 4% last year. What this is, is reflecting the impact of our high return D&C program. We have very high returns at the drilling and completion level, and those then positively impact the bottom line; it's what you would expect. Also on a per share basis, we can't be reporting very strong numbers, and we're not issuing shares in connection with large transactions that basically dilute your per share metrics. So our per share metrics will be exceedingly strong. Our ROCE will be exceedingly strong as well for 2018.

Finally, on the rainbow chart to the bottom right, this is something that we've had in for maybe a decade or so. But we've now adjusted this to be Brent oil price related. We are now essentially a Brent-priced company if you talk about our oil sales. And so the rainbow chart has been adjusted to reflect Brent as being the key oil price sensitivity. So just make a note of that for the future.

Now going to Slide 7. Production growth remains on a continuing positive trajectory. You can see that our fourth quarter guidance is shown in the rightmost column for 2018, 293,000 to 303,000 BOE out of Permian with oil production 188,000 to 194,000. Just a continuation of the same sort of execution and growth that we have seen over multiple quarters now, and as we continue on track with our a million in 10 goal for the future.

What I'm going to do now is pass it over to Joey. He'll give you some information on the Stackberry well results and an update on the results from our 3.0+ completion campaign for this year.

Thanks, Tim, and good morning to everybody. I'm going to be picking it up on Slide #8. And as Tim has already mentioned, our first Stackberry appraisal pad did come online in the third quarter and is showing strong early time results. Our goal in these tests is to understand how the Spraberry zones interact with each other in full development. We're basically combining our experience for nearly 1,200 wells completed to date, with a complex reservoir model that we're developing using cutting-edge science and technology, as you can see illustrated there in the bottom left. After 90 days on production, we have seen outperformance of approximately 35% over previous Spraberry wells across all 3 benches in the same area. And now we're going to gain invaluable knowledge on spacing, staggering, sequencing and stimulation of these Spraberry zones. Needless to say, we're extremely pleased with these early time results, and this 1 test alone has derisked approximately 50,000 surrounding acres, which allows us to transition the Spraberry intervals into our development plan with confidence.

I'm going to be moving on to Slide #9 where you'll see a summary of the Version 3.0+ completion results. The graph on the left represents every Version 3.0+ completion POP through Q3, and we've compared them to Version 3.0 wells in similar areas across the formations. You'll note the strong cumulative production outperformance to date of approximately 35% for the 3.0+ completions. And now the histogram in the bottom right shows the growth in the number of unique completion designs we've had over the past several years. As you can see, we've more than quadrupled the number of designs that we POP. As an example, there are roughly 15 unique designs associated with Version 3.0+ alone. Our acreage is larger than the state of Connecticut, and it has a diverse geology over multiple horizons. And as I've stated many times in the past, one size definitely does not fit all, and that makes it impossible for us to identify our completions in just a few buckets. Bottom line, we're focused on maximizing rate of return, and that requires a wide variety of completion designs. Overall, a very strong execution quarter for the Permian team.

And now I'll pass it on to Rich to discuss marketing.

Thanks, Joey. I'm going to start on Slide 10, where you can see that Pioneer's oil marketing efforts were a key differentiator for the quarter, and significantly improved our cash flow for the quarter. Specifically, the barrels that we purchased in Midland at the Midland Tank Farm and transported via our FT contracts to the Gulf Coast led to incremental cash flow of $189 million. Looking at this on a per barrel basis, our Gulf Coast sales was over $17 per barrel higher than the Midland prices that were in the mid-50s.

As we look at the fourth quarter, we're expecting a cash flow uplift, as Tim talked about, related to our FT of over $125 million. It's also worth reiterating what Tim mentioned that in November, our volumes that we transferred to Gulf Coast increased to 185,000 barrels a day from 165,000 barrels a day and will increase in January to 200,000 barrels per day. All of these barrels are expected to receive Brent-related pricing, increasing the company's cash flow and overall cash margins. Related to that, the company has derivatives in place now for 25,000 barrels a day of 2019 production that are tied to Brent prices, and future derivatives will also be tied to Brent prices.

Turning to Slide 11, and looking at Q3 earnings. Net income attributable to common stockholders was $411 million or $2.39 per diluted share. It did include noncash mark-to-market derivative gains of $38 million, and unusual items listed here really relate to our asset divestitures, and that included a gain on the West Panhandle sale of $114 million after tax, offset by other related charges, which is principally related to expensing future pipeline commitment fees related to our Raton divestiture. So adjusting for those unusual items, we're at $355 million or $2.07 per diluted share.

Looking at the bottom of the slide where we show Q3 guidance relative to results, you can see that all the items are within guidance or on the positive side of guidance for the quarter. And so overall, an excellent quarter for the company.

Turning to Slide 12. Looking at price realizations. You can see there, looking at the oil bar that oil prices for the quarter were up, including the benefits of FT contracts, by 5%. Without that benefit, and just subject to Midland pricing, we would have been down 6%. So once again the benefit of our FT contracts.

If you look at NGLs, NGL prices were up 25% quarter-over-quarter, really reflecting the significant improvement in ethane and propane prices for the quarter. Gas prices were up 12% to $2.21 per Mcf, reflecting the benefit of moving 70% of our gas out to the Southern California markets where it's priced on the SoCal index, and that netted an extra dollar per Mcf relative to Waha prices in the Midland Basin. So overall, you can see that our marketing strategy, moving our products to higher-priced markets, is significantly increasing cash flows and providing improved margins.

Turning to Slide 13. On production costs, you can see for the quarter that they were down $1 per BOE, relative to the second quarter or 9%. This decrease is principally related to the sale of our Raton and West Panhandle assets that had higher production costs, and that's reflected in the lower price per BOE, production cost per BOE.

Turning to Slide 14. We continue to have a very strong balance sheet with excellent liquidity. As Tim mentioned, our net debt for the quarter was down $200 million relative to the second quarter. We have no near-term maturities and really are in excellent financial position.

Turning to Slide 15. Q4 guidance, production forecast of 293,000 BOEs per day to 303,000 BOEs per day. And really, if you look at the rest of the information here, that guidance is similar to prior quarters, so I won't go through that. But in summary, we had a really an excellent quarter, as Tim mentioned. And we are on our way to a very strong fourth quarter.

So with that, I'll turn it back to Tim.

Thanks, Rich. And as we discussed today, we really have had an outstanding third quarter, and we expect this momentum to continue through the fourth quarter and into 2019. It's really too early to discuss our 2019 production and capital in detail, but the road map for 2019 will be to continue to prosecute the million in 10 plan just as shown on Slide #16. We'll continue to make decisions in the best interests of our stakeholders where we drive down costs, emphasize returns, focus on capital discipline, and take steps to more meaningfully return capital to shareholders in the next few months. We are, in fact, working on a number of specific initiatives that we'll be announcing over the next few months that will result in material capital savings and decreased well cost going forward. You can look for some of those announcements to come in the next few weeks. We expect that our capital budget for 2019 will come in at a point where it's below our operating cash flow, and therefore, we expect that we will generate free cash flow in 2019. We plan to have a full update on all of this in February as has been our practice in the past. It will be during our fourth quarter call in early February.

And with that, we'd like, Greg, for you to open up the call for any questions.

(Operator Instructions) And first, with Citi, we have Bob Morris.

First question. Joey, with the cost inflation that you noted last quarter, are the Version 3.0+ well completions still running at around $9 million all in?

Well, the incremental cost of Version 3.0+ completion compared to our standard completion is $1 million. And I don't know that I could actually create 1 bucket that explains what all of our well costs are because that varies across the lower Spraberry, Jo Mill, Wolfcamp A and Wolfcamp B, and also by geographic area. But in essence, the Version 3.0+ completions still costs about $1 million more per well.

Okay. And then separately, last quarter, you mentioned that the high line pressure on Targa would impact production in Q3 by 2,000 to 3,000 BOE per day. Did that end up actually being the case, and as we look at Q4? If so, is that something that's been resolved that you'll get that incremental production back here in Q4? Or how did that play out?

Yes, I think -- you're talking about -- Bob, are you talking about the new plant addition dropping the line pressure?

Yes. Because that's what you mentioned, it might impact Q3 production by 2,000 to 3,000 MBOE per day, and I didn't see any comment or reference to that in this release. I don't know if that was in it.

That's exactly right. We didn't put it in because it was just -- in the interest of time. But the plant did start receiving gas -- the plant in question is a Targa-related facility, the last week in September, and it has significantly reduced line pressures in the area, which is a huge positive on all of our flow rates. And I think from that standpoint, we'll continue to see the benefits of that as we get through the fourth quarter. The next Targa facility comes online in late February. Actually in the winter period of time, there is less issues related to line pressure simply because we use gas for the heater treater systems to make sure that oil is flowing in the colder weather period. So we think we're in good shape. The next plant comes on as I said, in late February. We'll continue to see the benefits of lower line pressures.

Next up, we have Doug Leggate with Bank of America Merrill Lynch.

Tim, I wonder if I could pick up on your last comment about generating free cash flow in 2019. The hedge book right now looks fairly light. I'm just curious if you can put some caveats around that in terms of your commodity assumptions. And given your balance sheet strength, how would you think about the use of free cash as you go forward? Because it does look like you're getting pretty close to an inflection point.

Well, I think we clearly are. Although I would cast it, Doug, we're sort of at an inflection point this quarter. This is a quarter where we actually generated free cash flow. So I think 2019, from an annual standpoint, will certainly be that same situation. Our assumptions in terms of when we refer to our current view of the budget in terms of capital and the resulting aspects of production growth and cash flow generation would -- are based on high 60s Brent, of course, depending upon what your view on the WTI Brent differential, what those views are. It could be a low 60 WTI or to mid-60s WTI. And from that standpoint, we think that's a reasonable price basis to go into looking at a budgeting cycle. Now of course, we are relatively lowly hedged in 2019 compared to '18, so we will be susceptible to lower prices if they were to occur. But by the same token, we have much more exposure -- upward pricing as well.

I am just curious, do you plan on -- normally you would go into the year significantly more hedged than you are today on a rolling basis. Would you plan to step up the hedging exposure between now and, let's say, the turn of the year?

Well, I think it's just a reflection of price. I mean, we feel there's opportunity presented by much higher prices than we see today. You have basically a flat curve today through 2019. So there's not a tremendous benefit above where prices are today in terms of looking out and hedging into the future. I think we'd hold off at these kind of prices and not do much hedging. If there's an opportunity to hedge substantially higher than where we are and guarantee a significant amount of free cash flow generation, we certainly would look at it. So we're going to be flexible. You asked the other question regarding what to do with the cash. That's something, of course, that we will be looking at over the next few months and we'll have some decisions to be made in that regard. But as I said, it's pretty clear that one of the things that we're going to be doing is evaluating steps to more meaningfully return capital to shareholders.

And if I can have a quick follow-up with Joey just on the Stackberry result. Joey, if I'm looking at the chart correctly, it looks to us at least that the Stackberry initial wells are at least as good as the Version 3 Wolfcamp wells. So I am just thinking -- just wondering, how do you think about layering this into your development options as to how you move the program forward now that you appear to be on -- well on your way to derisking that inventory?

Yes. As we stated in the -- as I stated in my comments and as I stated in the slide, this basically derisks 50,000 acres in that one particular area. And then we -- of course, we have 2 more tests coming online. We have one that came online in October and we're watching those results, and we'll have another one that will come online here in late November. And we'll be taking that all into account. I think it's -- there's no doubt that what this does is give us confidence that we can start placing these Stackberry wells into our development plan. But I would characterize it very similarly to how I do the Wolfcamp B and other appraisals that we do. We have such a vast array of acreage. It gives us confidence that we can start looking at how we time it, and how we put it in, but how we're going to start bringing it into 2019 is still up in the air. But it gives us confidence that we can put it in at any time in this particular area, and it will be too early to tell on the other 2 areas.

Moving on, from Raymond James, we have John Freeman.

When I look at Slide 9, I guess, for maybe first for Joey, with the significant number of the different completion designs, should we expect kind of as you learn more and more about all the various zones and the testing that you're doing that you have highlighted, that, that trend sort of continues? Will we get more and more of these sort of discrete completion designs? And I'm just kind of curious when you're kind of -- when you're formulating your budget, does it create like a meaningful range of -- or wider range of outcomes on sort of well costs and things like that?

Yes, there's no doubt. My team is celebrating today the depth of the Version 3.0+ and Version 3.0 taglines because you can see we have 45 different completion, and even on 3.0+, we have 15 different versions of that. And to answer your question, absolutely. Every one of those -- and I think this kind of illustrates the point. Every one of those has a different cost. Every one of those has a different result, and what we're trying to zero in on is returns. So as I look at the 2019 budget formulation, absolutely. You see various different completion recipes all throughout that plan, all with different costs. And again, we're focusing on capital efficiency and maximizing returns. So yes, it does add to what the plans look like going forward in multiple different scenarios.

Great. And then, Tim, obviously, just following up a little bit on your comments regarding certain steps on returning capital to shareholders will be forthcoming. And I'm just trying to, I guess, from a thought process in the past, you've kind of talked about really that's something that you wanted to think about more when you sort of reached the point of generating sort of excess cash flow from just operations. But I'm curious if either the recent divestitures and sort of the upcoming divestitures is kind of the combination of proceeds from those, and then just the massive cash balance if I'm sort of thinking about it the right way where you could potentially use that to sort of jumpstart some of those plans to kind of bridge the gap before you get to significant excess cash flow from just operations.

That's a great question, John. I think the way I look at it, we've got an arsenal of ways to deal with this question, both with regard to cash on hand prior to divestitures, to divestitures, to -- as you stated, free cash flow generative model in 2019. Those are all tremendous weapons to use at our benefit to try to solve for what's the optimal amount, and the correct amount of return of capital to shareholders. And that's exactly what we'll be doing. It is important, I think, from a fundamental standpoint, that we actually get this company to where we are in fact generating free cash flow, I think that's 2019. That's the point at which we've always said we're going to be evaluating this in a more significant way. And that's our messaging today.

Next question will come from Arun Jayaram with JPMorgan.

Tim, I wanted to get your thoughts on kind of the future of vertical integration at Pioneer. We've seen the company make some steps recently, including the U.S. Silica deal. And I know you're using a couple maybe third-party fleets. But how do you think about vertical integration over the 10-year? And I was wondering if you also could just elaborate on your commentary about some initiatives that you have under place maybe to improve the capital efficiency that you talked about in your prepared comments.

Yes, sure, AJ. First of all, our objectives when we look at these initiatives are really twofold. And those are to make sure we're very competitive in the sense of future cost on wells in our whole D&C program, and there's various initiatives that are required in order for us to do so, one of which you've seen us accomplish at least to some extent already in the U.S. Silica transaction I mentioned. The other, though, is to look at areas where we have capital going out the door that would have to be reconsidered or at least thought of differently perhaps in a world where we're trying to reduce capital spending. And so without going into a lot of detail, those are the company initiatives we're trying to do. The 100% focus, of course, is improving our capital efficiency through time and making sure that we are, in fact, a low-cost producer. When it comes to the vertical integration, this is something companies like ours who have invested in vertical integration have to assess from time to time as we look at an increasing rig count going into the future, of course, that's coupled with increasing needs for frac fleets. We have to assess whether we're going to invest ourselves or whether we're going to use third parties for that kind of future investment. So those are the type of things we're looking at today. Without any more detail, we will be announcing some initiatives in regard to various ways to cut costs and reduce capital spending over the next few weeks.

Great. And just my follow-up, Tim, lots of questions on your plans to return cash to shareholders. You do have quite a bit of cash on the balance sheet. Our question is you do have some investments in midstream thinking about your JV, in your gas processing plus the water system. What are your thoughts about potentially on a longer-term basis monetizing these midstream investing -- investments and returning cash to shareholders through this avenue?

Yes, I think if you look at gas processing, we've been very pleased to have a seat at the table with our equity interest over multiple years with Targa, our partner. And that has allowed us to make sure we can keep ahead of what's going on in terms of gas production in the basin, considering we are just one of the many producers which move gas through that system. In fact, we're about, any given day, 35% to 40% of the throughput volume. So we're also speaking for the other 60% in terms of what growth rates look like to make sure that the capacity is, in fact, there. So that has been an important investment for us. The water system is something that I would consider to be still under development. In fact, we are moving dirt and we are in the process of moving forward vis-à-vis our Midland water plant investment. Of course, that's going to take some time. We won't see first water from that until, let's say, the end of 2020 or so. But at the time it comes on, it will be 240,000 barrels a day of effluent water. And will quickly move us to a point where we will not be utilizing any significant amount of freshwater. And that's substantially looking forward in terms of making sure that we have the water capabilities to provide for that component of our capital needs to move our program forward. That said, we'll evaluate that -- these decisions as these processes move forward. Obviously, today, water is really early from the standpoint we're just in the process of building the facilities.

Next, we have Ryan Todd with Simmons Energy.

Maybe a quick follow-up on the midstream as you're speaking about that. I know you don't have official guidance for capital in 2019. But as we think about '19 and maybe '20 or just over the next couple of years, is there any meaningful change in the amount of capital expected to be spent on infrastructure as we look forward over the next couple of years?

I think if you look at midstream, for instance, the needs for gas processing will go up simply as a matter of the production of oil going up in the basin. And toward that end, I'm familiar with Targa's plans for 2019, which incorporate a couple of new plants as well as another plant -- 2 to 3 plants. One might be in early 2020 time frame. And so there will be continuing capital required in that business, yes.

Okay. And then I appreciate the commentary and the couple of different rigs to be added in December. How should we think about the potential pace and cadence of rig additions in '19? I know you don't have guidance, but in the past, you've kind of given this rule of thumb to time in terms of pace of rig additions. And maybe any rough estimate on what POPs could look like in 2019 relative to '18?

We're not going to be able to get in that level of detail, Ryan, until we establish it internally. We're still working on that. I mean, the fact is with more rigs will come more POPs. You can think of it somewhat ratably. Now what's happened recently is our level of efficiency of Drilling and Completions has gone up so dramatically that we have to assess that in our planning and decide exactly how that impacts the need for rigs. I mean, certainly in the models we've shown you in the past, we add a few rigs per year. I think what we'll try to do to deal with the 2019 program is to have a full year plan such that we probably would make sure we incorporate any rigs in calendar year '19 that would be effective only in 2020. There were rigs added in '19 that would then affect 2020 production, we'll put in the '19 capital budget. So that will be one change you see us do.

Next, we have Paul Sankey with Mizuho.

Tim, you mentioned that well, overall in the past, you've said that as you rise through your rainbow chart, as you call it, spending would go up with the oil price. It feels like with this result as you mentioned you have an inflection point that we're reaching a terminal level of spending in rigs. I think that's what I heard in the previous answer as well. Am I thinking about that the right way, which is to say, if the oil price was to go higher from here, you wouldn't be adding rigs and spending, given the performance that you're seeing from the existing activities that you've got? And given that you're essentially on track with your long-term target?

Yes, Paul. Just to clarify, our long-term plan does envision us adding rigs through time because it's necessary to offset what in effect becomes a larger base of declining wells through time. But what we said in the past, just to clarify, is that we're not going to accelerate activity in the face of higher prices. It doesn't make any sense because usually associated with higher prices come higher costs. And so, therefore, the last thing we want is accelerate into a declining margin scenario. So I think what you'll do is see us stick to our knitting in terms of our executing our plan. Price has become somewhat of an exogenous factor. And we'll be doing that through multiple years of hedge as part of our 1 million in 10 plan.

Right. So the increased CapEx you see in this year has essentially not been related to the higher oil price?

Well, I mean, yes. The higher oil price did have an effect on us, Paul, which we were very clear on last quarter, which had to do with -- we're in a different cost environment as a result of higher prices. And so what has affected us more in 2018 is just reflective of the fact that prices were higher, but not a difference in activity. We have added some rigs here, as I mentioned in my prepared commentary, at the end of December to prepare for, in essence, what amounts to 2019 production growth. And that's been well documented.

Understood. And then you sort of went away a little bit from just using the catchall Version 3 description. But how is the performance of these multiple different techniques that you're using differing now? And if you could just expand on that, if you like, in terms of how we think about the future performance of these wells?

I think I will let Joey answer that, Paul.

Well, I mean, just to be clear, where we tried these Version 3.0+ completions, they're in areas where we have a high confidence that they will be successful based on our extensive understanding of the 1,200 wells that we put on to date. But by no stretch of the imagination are we suggesting that Version 3.0+ completions work everywhere in every instance, and we don't execute our plan that way. That's part of the reason why we're trying to go away from that because the nuances of the completions just make it so much more difficult to put them into buckets. But in the areas where they do work, we're still seeing that they are yielding great promising results. But again, we're just focused on putting the right completion to maximize our returns. And that's what we're focused on going forward. It's very similar to the Stackberry and how we see that. It's a -- we've proven the concept that goes into our war chest, and now we're looking at putting together the best program we can each year that maximizes the returns. And so the deployment of Version 3.0+ wells in conjunction with where we can do some Stackberry tests and all these things, the more we prove these things up, the more optionality we have, which allows us to leverage our infrastructure and our tank batteries and our water, so that we can put together the most capital-efficient program we possibly can.

Moving on, we have Charles Meade with Johnson Rice.

I wanted to ask about the Stackberry test. And really, the 2 that, I guess the one that's flowing back now and the one that will soon be flowing back. This first one is on the Western Martin. And if -- looking at the rough math, it looks like you are going to derisk about a 5-mile radius around that test. Can you talk about where the next 2 tests are going to be geographically? And whether we should -- whether that's the right template to use about kind of the 5-mile radius of derisking? Or at some point will it be the case that you've done these in enough different kind of spots across your portfolio -- or across your asset, your footprint there that you can say, hey, we're derisking a lot more of that?

Yes, Charles. So the one that we put online this past month was in Midland County, kind of central Midland County. And then the one that we'll be putting online here not too long from now is in Southern Martin County. And to answer your question, I don't know that it's exact, but I would say general range of magnitude, that yes, we would expect that both these 2 tests would help us derisk a similar amount of acreage as the one that we are currently describing, which is in Scarborough Ranch.

Got it. That's helpful. And then Tim, perhaps this question might be best for you. You've done a lot of questions about things that -- assets that you'll be looking to divest that maybe outside of the core E&P operations. But when I think back over your trajectory over the last few years, one of the things that's really differentiated Pioneer from other operators is that you guys have been out in front in identifying pinch points that may emerge in addressing those. And you could see this happen with water, with sand, and you can make an argument that that's been the case as well with midstream and pressure pumping. So while it makes sense that at some point, you -- these investments mature and you want to move them on to different hands, are there other investments that you can talk about that you guys are considering that might not be on our radar now, but could be solving problems that's going to materialize 2 years down the line for you?

Well, I think if you look at the things that are currently at issue, the ones that have been well documented are clear. And in particular, we're talking about what's happening with pipeline limitations from the Permian oil in particular and gas. Gas, of course, gets mitigated somewhat as we get into the fourth quarter next year as the new pipeline to Auga Dulce also comes on stream. Similarly on oil, you got the 3 new pipelines coming out of Corpus, that gets solved. Today, for example, basically, frac space in Mont Belvieu is relatively tight. We think we're in pretty good shape on that, and are there will be some expansions early next year, so that gets solved. I think longer term, 1 pinch point that I think the industry is going to have to deal with is making sure we're prepared with electric transmission to make sure that we're in good shape on electricity supply. Right now, I think that's really not a pinch point, but it's something that we have to keep visuallying on mostly because it's not something we control. It's controlled by the PUC, the State of Texas, ERCOT and our energy supplier. So that's one thing that doesn't get much air time, but nonetheless it's something which we have to make sure we're focused on and continue like our other businesses to be planning long term.

Next, we have Michael Hall with Heikkinen Energy Advisors.

A couple of things to follow-up on. Maybe first on the marketing side. Now obviously, we've got some movement in differentials and that's expected to narrow out next year. But at the same time, you guys are ramping barrels that you're moving to the coast. Just curious if you'd be willing to provide some kind of broad strokes around what you think that marketing income might look like over the course of 2019. Or maybe directionally, how it looks relative to the fourth quarter run rate, any color you're willing to provide.

Yes, Mike. I'd say when you look at the forward curve is probably the easiest way to look at it and look at where the Brent WTI differential is, which is running right around $9 or $10 recently for 2019. So I think that gives you an indication of one piece of it. And then if you look at the Midland differentials relative to WTI, it varies next year from call it $5 down to about $2. So put it in that $3 range. So all in, you're looking at $12, and our cost to do that is about $6 to all in from there. So that's kind of the differential, and you can kind of do the math, then, of what that would mean from an uplift the company would receive over Midland pricing.

And what total amount of volume can you move next year, you think, through all these contracts?

I think it starts at 200,000 a day and grows probably to 225,000 or so by the end of the year.

Okay, that's helpful. And then on the NGL realization side, sorry if I missed any questions on this, I dropped for a minute. But the -- very strong realizations, some of the best we've seen, I think, in the quarter. Is that sustainable relative to maybe a blended Belvieu barrel or relative to WTI, however you want to think about it? Is that kind of a sustainable run rate, you think? Or yes, any thoughts on that going forward?

No, I don't think it's sustainable only because what's happened with NGL prices since the end of the quarter. I mean, if you look at what's happened in October, ethane prices, propane prices and really the whole wide grade barrel has fallen. So that was really a product of where commodity prices were during the third quarter that we benefitted from and will still be getting market prices for our NGL barrels in Mont Belvieu for the fourth quarter, and so that reflects the lower forward curve.

Moving on. From TPH, we have Matt Portillo.

Just one question from me. Tim, given your peer leading inventory [is up] and focus on the modest pace of development going forward, is there the potential at some point to look at a carve-off of longer dated inventory, essentially bringing additional cash in the door, and hopefully closing the gap on the discounts of intrinsic value per shares?

Great question, Matt. It's certainly something that we have as a top-of-mind issue. For the time being, I think our main objective is to evaluate our whole acreage position. Just like any acreage position and inventory, we have some areas that won't come with a premium in a sense that it's where it stacks up and when it's going to get drilled. So we've some acreage, some areas that just won't compete relative to some of our core, the core acreage. So we're actually doing an inventory of all this acreage from an economic standpoint and certainly going to begin the process by looking at that acreage which won't make the cut from an economic standpoint using any kind of reasonable set of assumptions. And that's being done by our business development team as we speak. So you can expect it will have a goal set for 2019 to divest certain assets that we think won't make the cut. After that, everything else is under consideration, realizing we do have quite a long inventory in terms of really measured in decades. We've got to assess exactly what the next steps are in that regard.

Next, from SunTrust, we have Neal Dingmann.

Tim, you've mentioned this several times on the call. You guys obviously are outstanding on the financial side. But I've had some questions just for people asking about on the gas processing side. You obviously have a large facility there. I know I've talked to Neal about this in the past about just your thoughts about what to do with that. I mean, do you continue building that up, you monetize. How do you think about that facility given sort of the success you've had with monetization and other things like that in the past?

Yes. As I mentioned in my earlier comments, Neal, I think that this has been quite an outstanding partnership between Pioneer and Targa, which has allowed us to keep ahead of gas processing requirements in the basin, again, not just ours but others as well. Plants will need to continue to be built, so we've got to make assessments as to whether we want to continue investing in those. And that's simply going to be decision we make going forward. So I think certainly it's been a good set of investments for us. We have to assess that as we go forward.

Okay. And then, Tim, looking at Slide 21, obviously, your FT is -- there's nobody second to you right now on this. The exports continue to climb. How do you sort of mix? I know you mentioned that in the earlier slide, you're now relating that to Brent. But I guess my overall question is will exports be -- continue to become a larger and larger piece of the business? Or how do you sort of view when you start sort of diversifying your take away?

Well, I think the fact is with the Permian Basin growing as fast as it is and that being all, relatively speaking, light sweet crude oil, there really is no alternative for the entire industry other than to export. We're going to satiate U.S. refining capacity demand for this type of oil, even though there are a couple of expansions underway, within a relatively short period of time based on that growth rate. The industry has no choice but to export these volumes as a result. We just happen to be at the forefront of being prepared for this, and are taking advantage of it with, as Rich mentioned, at the point where we will have 200,000 barrels a day being exported. That's a substantial amount of world oil demand being met by Pioneer's individual net volumes. That said, the very -- the big positive about this is we're seeing that this oil is in good demand in the world markets. In particular, this light sweet brand of crude oil works in a world where we're trying to reduce sulfur content in motor fuels and in maritime-related fuels. So it's right down the alley of some of the big refining centers. Right now, because of what's going on in Asia, we're probably balanced more 60% to Europe, 40% to Asia. Prior to the issues with Chinese trade, we probably were more in the other side of the coin, 40-60 in terms of 60% going to Asia. But we'll always find that there's opportunities in the world to take this oil. Furthermore, everyone would prefer to take U.S. oil supply versus countries for which there's a lot more political risk. So we're seeing dramatic increases in demand and that's where this oil is going. So we're at the forefront of that, really a major industry player now when it comes to the market for this type of oil.

And next we have Derrick Whitfield with Stifel.

Perhaps for Joey, referencing Page 9 of your PowerPoint and the bottom right chart specifically. If you were to speak to 1 interval only, how many unique completion designs would you have across your position?

Just 1 interval only? I don't know that it would -- well, it would be slightly different. But I would say just in the Wolfcamp B, and I'm just purely guessing here. You're still going to have 20 plus. Sometimes, whenever you go to the Lower Spraberry Shale and things, or intervals like that, we've discovered stage length isn't as much of a driver as it is in other areas. So there are some things that are distinct between intervals. But even across Wolfcamp B and Wolfcamp A, we have a wide variety of completion designs.

Got it. That's very helpful.

I think the answer to the question, is there's really -- it's not one-size-fits-all even by interval.

Very helpful. And as my follow-up perhaps for Tim. There's been a lot of discussion this quarter on efforts across industry to optimize spacing and minimize detrimental parent-child relationships. You guys are clearly more conservative than most of your peers with spacing in the Wolfcamp, but you also have materially more inventory than your peers. If your position were a 100,000 acres or less, would your development approach still be biased towards 750-foot spacing or water in the Wolfcamp?

Derrick, this is the best question I've got in a long time because it shows some insight into what's going on in the industry. I wouldn't call us conservative. I would call us value optimizing. I would call us maximizing economics. What I mean by that, and I referred to this a little bit in my earlier commentary. If you don't have enough inventory, what you do is you basically drill the hell out of it. And you basically drill so many wells, the concept being we're going to drill 1 more well to squeak out 1 more dollar of it -- of NPV. Because that's the only alternative we have when we have limited acreage. And what that means, the last economics on the last well drilled are lousy. We're taking the opposite view. We want the economics on every single well to be very, very strong. We stop when we start seeing degrading of economics on a per well basis. We don't care about maximizing NPV per section because you're going to drill uneconomic wells to make that happen relative to our alternatives. We're blessed with vast inventory, which really helps us to stop when we start seeing diminishing returns in a section by drilling it too far down space. So I don't think we're conservative. I think we're the beneficiary of our acreage position.

And next, we have Brian Singer with Goldman Sachs.

Going back to the well cost initiatives that you're taking, can you talk about the magnitude that, that could bring to reducing well costs and what U.S. Silica does? And when you think about or when we should think about what some of the ones that are yet to be announced are, are they more contractual like U.S. Silica? Are they more process-driven efficiencies? Or are they initiatives in which you actually spend some capital, but you'll get a return on that capital via lower well cost?

Well, let's just talk about the style of the U.S. Silica deal and what that means. To the extent that we are in effect with that contract delivering sand at about 50% of our alternative today, if you then consider if that were to be applicable across a broader swath of our sand needs, unless you say it were to be 100% of our sand needs, it would be saving us $400,000 or $500,000 per well. So I would call that dramatic in its own right. Some of the other initiatives we're looking at are -- on the one hand, intended to give us long-term cost advantages on D&C, and some of them are just related to cutting capital and putting us in a good contractual situation. I'm going to leave it at that. But suffice it to say, all these initiatives are based on improving our economics, improving our returns and those will be substantial improvements.

Great. And then you talked a little bit about just some of the pipes -- exogenous pipeline risks, but I guess beyond that as you prepare for 2019, what do you see as the key areas of potential risk around execution? And what are the mitigation efforts that you and the team are taking now?

I think we're well situated for 2019, Brian. As you look at -- of course, we have a much more long-term planning approach. It's what happens when you establish long-term goals. So every time a team comes in to talk to us about what they're trying to achieve to actually mitigate risks, it's about what are they doing to meet those long-term goals. So we have pipeline space locked up for FT for both gas, oil and NGLs that cover us easily in the case of oil to early 2021 or '22. So we'll be working on pipeline deals, but that is not going to affect 2019. If you look at our water supply today, we're moving about 500,000 barrels of water to our locations every day, because we have a large water system that allows us to do so. We're moving ahead on sand as we discussed. And you'll probably see some more news on our ability to make sure we can increase those savings as well. So it's across this whole broad range of initiatives that I can say 2019 is somewhat to the point where we could say most of the issues, if we had any, were already mitigated. Realizing we always have 3 years' worth of wells already scripted in advance. So there may be issues and maybe things that could occur. You can't ever rule out bad weather as an example, and we've seen that in the past. Right now, we're setting ranges for production that incorporate bad weather potential in our basin, and I think those won't affect us from the standpoint of ability to meet our targets. But other than that, I feel very good about our execution. And our objective is to take the kind of momentum we've seen here in third quarter, take it into fourth quarter, and take it into 2019. I see no reason why we shouldn't be able to do that.

Ladies and gentlemen, that does conclude our question-and-answer session. I'd like to turn the floor back to President and CEO, Tim Dove.

Thank you, Greg. I appreciate everybody being on the call. I also want to make sure everybody has a great Thanksgiving. Thanksgiving is important for the country. It's important for all of our families, and I wish all of you a very happy Thanksgiving, and for that matter, holiday season following that. We'll be looking forward to giving you some updates in the interim, as I said, regarding some of these initiatives. At the same time, we'll really be looking forward to our call in February, where we can outline our 2019 plan. Thanks, everybody, for being on the call.

Ladies and gentlemen, that does conclude our conference for today. Thank you for joining us once again. You may now disconnect.